The use of the Steam Assisted Gravity Drainage (SAGD) technique using pairs of parallel steam injection and oil production wells has resulted in the production of very hot fluid rising at high flow rates through the upwardly extending riser portion of the production wellbore to the surface. Saturation conditions are encountered in the riser, resulting in behavior analogous to gas lifting (steam lift). Due to the large release of energy of flashing water, however, the flow in the riser is unstable. These instabilities are the same phenomenon that drive cyclic eruptions in geothermal geysers.
When flowing a conventional vertical well produced with a steam drive, the fluid rate is relatively low (typically 10 m.sup.3 /d.)Heat is given up through the wellbore to the surrounding formation, cooling the produced fluid and avoiding flashing.
Commercial implementation of the SAGD technology can produce fluid rates of 300 m.sup.3 /d and upwards to levels in excess of 1000 m.sup.3 /d. At these high rates, the fluid does not cool significantly en route to the surface.
SAGD uses a horizontal production well located in a viscous oil reservoir, producing heated oil which gravity drains from a steam chamber located around a steam injection well above and closely parallel and co-extensive to the production well. SAGD is in development at the AOSTRA Underground Test Facility (UTF) located in Northern Alberta, Canada. The SAGD is described in various publications by R. M. Butler et al., U.S. Pat. No. 4,344,485 issued to Butler, and Canadian patent 1,304,287 issued to applicant.
As the fluid flows up the riser portion of the well, the hydrostatic head on the fluid diminishes (there being less fluid above to compress the fluid below) and the pressure drops. When the pressure of the fluid reaches the saturation pressure of water, then contained water flashes to steam. At higher fluid temperatures, the fluid pressure may only reduce a small amount before the saturation pressure is reached and flashing occurs.
When water contained in the well flashes to steam then tremendous energy is released. At downhole pressures of 1700 kPa (absolute), the volume that the produced steam displaces is over 100 times the volume of water from which it was formed. The saturation temperature of steam at 1700 kPa is about 200.degree. C. Steam can increase its volume over 1600 times at atmospheric pressures and 100.degree. C. The large expanding volume of the generated steam results in a violent attempt to expel the fluid which is above the location of the flash.
With a constant pressure wellhead, the fluid is released in a surge. Further, the removal of the initial fluid releases the hydrostatic back-pressure on the remaining fluid resulting in a progressive "flash front" which propagates successively downwards in the riser, ejecting the remaining hot fluid. When the energy of the high velocity steam flow eventually diminishes, the riser refills. Once the riser refills, the flow of hot fluid resumes, re-initiating a cyclical periodic repeating of this geyser-like behavior.
The instability associated with periodic geyser behavior is destructive to achieving steady and efficient production.
In conventional oil-production applications, when a downhole pump is used, backpressure can be maintained at the wellhead, preventing the saturation pressure from ever being reached. However, in the SAGD situation the flow rates are so high that pumping is expensive and difficult. The largest downhole pumps are capable of pumping only about 750 m.sup.3 /d and temperatures are prohibitively high for the sealing components at 200.degree. to 300.degree. C. Therefore, the use of formation pressure or steam lifting is an attractive alternative to pumping if the flashing can be controlled.
Conventional attempts to control the steam-lifted flow with manual adjustments of a production choke at the wellhead results in the initiation of a strong positive feedback action-response cycle. This cycle results during both an attempted increase and a reduction in the flow.
As the choke flow is manually reduced, the bottom hole pressure increases, which in turn further reduces the flow rate from the reservoir. Dependent upon the characteristics of the reservoir, several outcomes are predictable:
if the reservoir pressure is below the hydrostatic head of the column of liquid in the riser, then the well will die; or PA1 if the reservoir pressure is greater than the hydrostatic head then the well exhibits cycling geyser behavior. PA1 a fluid production choke means located at the top of the conduit for adjusting the mass flow rate of the hot fluid issuing therefrom; PA1 a mass flow detection means downstream of the production choke means for repetitively producing signals indicative of the mass flow rate of hot fluid flowing therethrough; PA1 a first mass rate control means, associated with the mass flow detection means and the production choke means, for controlling the mass rate of fluid through the choke; PA1 measurement means for repetitively producing process signals related to optimal production of the fluid; and PA1 a second controlling means for receiving the process signals and being cascaded to the first controlling means for modifying the output of the first controlling means when process signals indicate that the mass rate requires adjustment to achieve optimal production of fluid; PA1 the hot fluid is produced at a substantially constant mass rate over a short time interval using the first mass rate controller and production choke means, whereby two-phase flow is stabilized; and PA1 the mass rate of flow of the hot fluid is adjusted in response to the process signals, over a time interval which is large relative to the short time interval of the first mass rate controller whereby the mass rate of fluid flow may be controlled at an optimal level.
If the flow rate from the well is manually increased, the bottom hole pressure decreases, causing a further increase in the flow. If the positive feedback cycle is not interrupted then the well can overdraw the reservoir and produce massive volumes of driving steam.
It is an object of the present invention to provide a method for controlling the well to stabilize the flow of hot fluid up the riser, avoiding the cyclic instabilities described hereinabove.